Seismic data acquisition and processing may be used to generate a profile (image) of geophysical structures under the ground (subsurface). While this profile does not necessarily provide an accurate location for oil and gas reservoirs, it suggests, to those trained in the field, the presence or absence of such reservoirs. Thus, providing a high-resolution image of the subsurface is important, for example, to those who need to determine where the oil and gas reservoirs are located.
Seismic data acquisition generally employs multiple impulsive sources (e.g., explosive or airgun sources) or continuous sources (e.g., “vibroseis” vibratory sources) that release seismic energy when triggered. These or other seismic sources are positioned with respect to geophone or hydrophone receivers and then activated. Once activated, impulsive sources produce a generally short, sharp shock, and vibrators generate a sweep that typically lasts between five and twenty seconds and typically spans a predetermined range of frequencies. A recording system records the response data measured at the receivers. For reflection seismology, the record length is typically set to equal the sweep length plus a listen time equal to the two-way travel time, which is the time required for the seismic energy to propagate from the source through the Earth to the deepest reflector of interest and back to the receiver. The sources are then moved to a new source location and the process is repeated. As used herein, the term “shot” refers to the energy produced by a seismic source when activated (whether impulsive or vibratory); the terms “shoot” and “fire” refer to the activation of a seismic source. Conventional data-analysis techniques often process data collected by assuming a stationary receiver after firing a stationary source (or a source which can be considered to be, from a data processing perspective, stationary (for example, an ocean bottom survey using fixed receivers)) as described below. An example of such techniques is Wiener (least-squares) filtering, which is used to compensate for known sources of error or contamination in the recorded data, such as a non-ideal source waveform.
During a seismic survey, the measurable response D(t) (the signal recorded with a seismic sensor) is considered to be composed of the impulse response of the Earth G(t) convolved with the Earth attenuation E(t) and the farfield waveform P(t) of the seismic source, plus some noise N(t). In 1D this can be expressed as a convolution (“*”) in the time domain:D(t)=[P(t)*G(t)*E(t)]+N(t)  (1)An initial seismic data processing step attempts to recover the Earth impulse response G(t) from the measurable quantity D(t). To achieve this, the shape of the far-field waveform P(t) is measured or otherwise determined and used in Equation (1). In practice this involves convolving the inverse of P(t) with D(t). The farfield waveform P(t) may be a few hundred milli-seconds to several seconds in length.
In conventional marine seismic acquisition, a vessel tows plural streamers having multiple seismic receivers configured to record seismic data. The vessel also tows a seismic source, e.g., an airgun, which imparts seismic energy into the water. The seismic energy travels toward the subsurface and is partially reflected back towards the sea surface. The seismic recorders record the reflected seismic waves. The vessel generally moves at a constant speed and shoots at regular time intervals. Shooting while in motion significantly increases the amount of data that can be collected in a given amount of time, since it does not require time to accelerate and decelerate between shots. Conventional analysis techniques used for seismic data collected from stationary sources can, in general, still be used for marine airgun data. This is because the airgun is an impulsive source and the water exerts drag on the bubble produced in the water by the airgun, effectively making that bubble stationary until the energy from a given shot has dissipated.
However, there is a need for more flexibility in selecting source waveforms and other seismic-source characteristics. For example, environmental regulations may restrict the use of impulsive sources in some jurisdictions. Under such regulations, it may be preferable to use vibratory sources instead of synchronized airgun arrays. However, with regards to marine operation, keeping stationary while shooting a vibratory source can be very difficult. Moreover, the time to bring the vessel up to speed, navigate to the next shot point, and decelerate to station-keeping would dramatically reduce the amount of data collected per day of marine operation. The alternative is to operate the vibratory source while the vessel is in motion. Accordingly, there is a need for techniques for processing seismic data from non-impulsive, moving sources, which conventional techniques cannot do.
FIGS. 1A-2B show examples of a difficulty encountered in continuous-data processing by contrast with impulsive-source processing. When an impulsive source is fired with standard data acquisition, the subsequent recording time is selected so that substantially all useful reflected/diffracted energy is recorded before the next shot fires. This delay time imposes constraints on the acquisition rate and, hence, increases the cost of acquisition.
In this regard, FIG. 1A shows sources being actuated at different spatial positions 10, 12 and 14 with delay time such that the recorded wavelets 10a-c corresponding to spatial position 10 do not interfere (in time) with wavelets 12a-c corresponding to spatial position 12. The signal recorded at the receiver (e.g., a stationary receiver) can be considered as a continuous recording (16) or separated to form regular seismic traces for each individual shot as shown in FIG. 1B. The traces as illustrated in FIG. 1B form a receiver gather 20. Each vertical trace in the receiver gather 20 relates to a different shot and has a different position on axis X, and each wavelet has a different time on a temporal axis t. FIGS. 1A and 1B can respectively represent, for example, multiple shots being fired by a seismic-survey vessel as it sails, and the data collected by a stationary receiver such as an ocean-bottom node (OBN).
To reduce the acquisition time, it is possible to simultaneously shoot two or more sources. Acquisition of simultaneous source data means that the signals from those sources interfere at least for part of the record. By acquiring data in this way, the time taken to shoot a dataset is reduced along with the acquisition costs. As an alternative to reducing the acquisition time, a higher density dataset may be acquired in the same time. For such data to be useful, it is necessary to develop processing algorithms to handle source interference (cross-talk noise). Such algorithms permit determining which of the observed subsurface reflections is associated with each source. This is referred to as “deblending” the data.
FIG. 2A shows a source configuration similar to that of FIG. 1A, but with the sources simultaneously activated so that, for example, the wavelet 10c is superposed (in time) with the wavelet 12a. FIG. 2B shows the receiver gather 30 formed though pseudo-deblending. Pseudo-deblending involves forming regular seismic traces from the continuous recording based on the start time of the actuation of each shot with no attempt to mitigate cross-talk noise. The data of FIG. 2B has been shot in less time than the data in FIG. 1B, but cross-talk 32 is observed and noise on one trace is signal on another trace.
A continuous source is the limit of a series of shots as the time between shots approaches zero. Accordingly, the noise and cross-talk 32 visible in FIG. 2B are representative of the type of effects that must be compensated for in order to effectively use data from continuous sources. Present “designature” techniques for processing continuous-source data, e.g., for vibroseis sources, require the source to be stationary while operating. Accordingly, there is a need for ways of processing data that will permit continuous sources to be used while moving, e.g., during marine operations.
Moreover, as the source changes position with respect to the Earth, variations in the angle of subsurface features with respect to the incident seismic energy can change the angle of reflection of that energy. When the source takeoff angle and the receiver incoming angle differ relative to the respective directions of motion of the source and the receiver, the seismic signal will undergo a Doppler shift, and the receiver will detect a frequency different from the frequency emitted by the source. Various techniques have been described for compensating for error introduced by Doppler shifts, e.g., U.S. Pat. No. 4,809,235 to Dragoset, Jr., and U.S. Pat. No. 6,151,556 to Allen, each of which is incorporated herein by reference. However, various of these techniques are limited to frequency-sweep source emissions. Accordingly, there is a need for a way of compensating for Doppler shift while still permitting various types of source signals to be used.
For completeness, reference is made to the following papers: “Effects of Source and Receiver Motion on Seismic Data,” Gary Hampson and Helmut Jakubowicz (Texaco Ltd., England), 1990 SEG, pp. 859-862; “The Effects of Source and Receiver Motion on Seismic Data,” Gary Hampson and Helmut Jakubowicz, Geophysical Prospecting, 1995, 43, 221-224; Hampson, D. 1986, “Inverse velocity stacking for multiple elimination,” Journal of Canadian Society of Exploration Geophysics, 22, 1, 44-55; Hubbard, T. P., Sugrue, M. J., Sandham, W. A., and Booth, E. A., 1984. “Marine source and receiver deghosting and array inversion in F-K space,” 46th EAEG Meeting, Abstracts, p 26; Trad, D., Ulrych, T. and Sacchi, M. 2003, “Latest views of the sparse Radon transform,” Geophysics, Vol. 68, no 1, pg. 386-399; Van der Schans, C. A. and Ziolkowski, A. M., 1983, “Angular-Dependent Signature Deconvolution,” SEG conference proceedings, pages 433-435; and Ziolkowski, A., Parkes, G. E., Hatton, L. and Haugland, T., 1982, “The signature of an airgun array: computation from near-field measurements including interactions,” Geophysics 47, 1413-1421. However, these papers do not satisfy the afore-described needs which are present in today's seismic data processing techniques.